Novel Modified Acid Compositions as Alternatives to Conventional Acids in the Oil and Gas Industry

ABSTRACT

An aqueous modified acid composition for industrial activities, said composition comprising: an alkanolamine and strong acid in a molar ratio of not less than 1:15, preferably not less than 1:10; it can also further comprise a metal iodide or iodate. Said composition demonstrates advantages over known conventional acids and modified acids.

FIELD OF THE INVENTION

This invention relates to compositions for use in performing variousapplications in various industries including but not limited to the oil& gas industry, more specifically it relates to the use of alkanolaminesto create an aqueous modified acid composition as an alternative toconventional mineral and organic acids for use over a broad range oftemperatures and applications.

BACKGROUND OF THE INVENTION

In the oil & gas industry, stimulation with an acid is performed on awell to initiate, increase or restore production. In some instances, awell initially exhibits low permeability, and stimulation is employed tocommence production from the reservoir. In other instances, stimulationor remediation is used to further encourage permeability and flow froman already existing well that has become under-productive due to scalingissues, wellbore damage or reservoir depletion.

Acidizing is a type of stimulation treatment which is performed above orbelow the reservoir fracture pressure in an effort to initiate, restoreor increase the natural permeability of the reservoir. Acidizing isachieved by pumping acid, predominantly hydrochloric acid, into the wellto dissolve typically limestone, dolomite and calcite cement between theacid insoluble sediment grains of the reservoir rocks or to treat scaleaccumulation.

There are three major types of acid applications: matrix acidizing,fracture acidizing, and breakdown or spearhead acidizing (pumped priorto a non-acid fracturing pad or cement operation in order to assist withformation breakdown (reduce fracture pressures, increased feed rates),as well as clean up left over cement in the well bore or perforations. Amatrix acid treatment is performed when acid is pumped into the well andinto the pores of the reservoir formation below the formation fracturepressure. In this form of stimulation, the acids dissolve the sedimentsformation and/or mud solids that are inhibiting the permeability of therock, enlarging the natural pores of the reservoir (wormholing) andstimulating the flow of hydrocarbons to the wellbore for recovery. Whilematrix acidizing is done at a low enough pressure to keep fromfracturing the reservoir rock, fracture acidizing involves pumping acidinto the well at a very high pressure, physically fracturing thereservoir rock and etching the acid reactive portion of the formation.This type of acid treatment forms channels or acid etched fracturesthrough which the hydrocarbons can flow, in addition to forming a seriesof wormholes. In some instances, a proppant is introduced into the fluidwhich assists in propping open the fractures, further enhancing the flowof hydrocarbons into the wellbore.

The most common type of acid employed on wells to stimulate productionor undertake remedial work is hydrochloric acid (HCl), which is usefulin stimulating carbonate reservoirs.

Some of the major challenges faced in the oil & gas industry from usinghydrochloric acid include the following: extremely high levels ofcorrosion (which is countered by the addition of ‘filming’ typecorrosion inhibitors that are typically themselves toxic and harmful tohumans, wildlife, the environment and equipment). Reactions betweenmineral acids and various types of metals can vary greatly but softermetals, such as aluminum and magnesium, are very susceptible to majoreffects causing immediate damage. Hydrochloric acid produces hydrogenchloride gas which is toxic (potentially fatal) and corrosive to skin,eyes and metals. At levels above 50 ppm (parts per million) it can beImmediately Dangerous to Life and Health (IDHL). At levels from1300-2000 ppm death can occur in 2-3 minutes.

The inherent environmental effects (organic sterility, poisoning ofwildlife etc.) of acids in the event of an unintended or accidentalrelease on surface or downhole into water aquifers or other sources ofwater are devastating and can cause significant pH reduction of such andcan substantially increase the toxicity and could potentially cause amass culling of aquatic species and potential poisoning of humans orlivestock and wildlife exposed to/or drinking the water. An unintendedrelease at surface can also cause hydrogen chloride gas to be released,potentially endangering human and animal health. This is a common eventat large storage sites when tanks split or leak or during trafficaccidents with trucks handling HCl. Typically, if near the public, largeareas need to be evacuated post event and a comprehensive, expensive toimplement, emergency evacuation plan needs to be in place prior toapproval of such storage areas. Because of its acidic nature, hydrogenchloride gas is also corrosive, particularly in the presence ofmoisture.

The inability for mineral acids with common corrosion control additivesand blends of such to biodegrade naturally results in expensivecleanup-reclamation costs for the operator should an unintended releaseoccur. Moreover, the toxic fumes produced by mineral & some organicacids are harmful to humans/animals and are highly corrosive and/orproduce potentially explosive, toxic and/or corrosive vapours.Transportation and storage requirements for acids are restrictive andtaxing. As well, the dangers surrounding exposure by personnel handlingthe blending of such dangerous products constrict theiruse/implementation in areas of high risk such as within city limits andenvironmentally sensitive areas such as offshore

Another concern is the potential for exposure incidents on locations dueto high corrosion levels, even at ambient temperatures, of acids causingpotential storage tank failures and/or deployment equipment failuresi.e. coiled tubing or high pressure iron failures caused by highcorrosion high rates (pitting, cracks, pinholes and major failures).Other concerns include: downhole equipment failures from corrosioncausing the operator to have to execute a work-over and replace downhole pumps, tubulars, cables, packers etc.; inconsistent strength orquality level of mineral & organic acids; potential supply issues basedon industrial output levels; high levels of corrosion on surface pumpingequipment resulting in expensive repair and maintenance levels foroperators and service companies; the requirement of specializedequipment that is purpose built to pump acids greatly increasing thecapital expenditures of operators and service companies; and theinability to source a finished product locally or very near its end use;transportation and onsite storage difficulties.

Typically, acids are produced in industrial areas of countries locatedsome distance from oil & gas producing areas, up to and sometimes over10 additives can also be required to control various aspects of theacids properties adding to complications in the handling and shippinglogistics. Having an alternative that requires minimal additives is veryadvantageous.

Extremely high corrosion and reaction rates with temperature increasecauses conventional mineral acids to spend/react or “neutralize” priorto achieving the desired effect such as deeply penetrating an oil or gasformation to increase the wormhole or etched “pathway” effectively toallow the petroleum product to flow freely to the wellbore. As anotherexample, hydrochloric acid can be utilized in an attempt to free stuckdrill pipe in some situations. Prior to getting to the required depth todissolve the formation that has caused the pipe/tubing to become stuckmany acids spend or neutralize on formation closer to the surface due toincreased bottom hole temperatures and greatly increased reaction rate,so it is advantageous to have an alternative that spends or reacts moremethodically allowing the slough to be treated with a solution that isstill active, allowing the pipe/tubing to be pulled free.

When used to treat scaling issues on surface equipment due to producedor injected water mineral precipitation, conventional acids are exposedto human and mechanical devices as well as expensive equipment causingincreased risk and cost for the operator in the event of corrosionrelated issues. When mixed with bases or higher pH fluids or even water,strong acids will create a large amount of thermal energy (exothermicreaction) causing potential safety concerns and equipment damage, acidstypically need to be blended with fresh water (due to their intoleranceof highly saline water, causing potential precipitation of minerals) tothe desired concentration requiring companies to pre-blend off-site asopposed to blending on-site with sea or produced water therebyincreasing costs associated with transportation.

Conventional mineral acids used in a pH control situation can causerapid degradation of certain polymers/additives requiring increasedloadings or chemicals to be added to counter these negative effects.Many offshore areas of operations have very strict regulatory rulesregarding the transportation/handling and deployment of acids causingincreased liability and costs for the operator. When using an acid topickle tubing or pipe, very careful attention must be paid to theprocess due to high levels of corrosion, as temperatures increase, thetypical additives used to control corrosion levels in acid systems beginto degrade very quickly (due to the inhibitors “plating out” on thesteel or sheering out in high rate applications) causing the acids tobecome very corrosive and resulting in damage to downholeequipment/tubulars. Conventional acids can be harmful to many elastomersand/or seals found in the oil & gas industry such as those found in blowout preventers (BOP's)/downhole tools/packers/submersible pumps/sealsetc. Having to deal with spent acid during the back-flush process isalso very expensive as these acids typically are still at a low pH andremain toxic and corrosive. It is advantageous to have an acid blendthat can be exported to production facilities through pipelines that,once spent or applied, is much higher than that of spent HCl, reducingdisposal costs/fees. Also, mineral acids will typically precipitate ironand/or minerals solubilized during the operation as the pH of the spentacid increases causing facility upsets and lost production. It isadvantageous to have a strong acid that will hold these solubilizedminerals and metals in solution even as pH rises dramatically close toor above a neutral state, greatly reducing the need to dispose of spentacids and allowing them to be processed and treated in a more economicalmanner. Acids are used in the performance of many operations in the oil& gas industry and are considered necessary to achieve the desiredproduction of various petroleum wells and associated equipment, maintaintheir respective systems and aid in certain drilling, remedial andcompletion operational functions (i.e. freeing stuck pipe, filter caketreatments, stimulation and scale treatments). The associated dangersthat come with using mineral acids are expansive and it is thusdesirable to mitigate them through controls whether they are chemicallyor mechanically engineered.

Eliminating or even simply reducing the negative effects of strong acidswhile maintaining their usefulness is a struggle and risk for theindustry. As the public and government demand for the use of lesshazardous products increases, companies are looking for alternativesthat perform the required function without all or most of the drawbacksassociated with the use of conventional acids.

While some modified acids have overcome some problems emanating from theuse of strong acids, their reactivity becomes a concern for the userwho, in some cases, would need a fast acting acid such as a conventionalmineral acid like 15% HCl, commonly utilized as a spearhead treatmentacid. The careful balancing of increased safety (i.e. less fuming orvapor pressure less corrosive to metal and dermal tissue, transportissues) while retaining a quick reaction time is a challenge foroperators.

There are a range of hydraulic fracturing techniques and severaldifferent approaches may be applied within a specific area. Hydraulicfracturing programs and the fracture fluid composition vary based on theengineering requirements specific to the formation, wellbore mineralogy,porosity and permeability and location. However, water-based frackingtechniques typically requires the following four steps: the spearhead orbreakdown acid step; the pad step; the proppant step; and the flushstep. In the spearhead step, which is commonly referred to as an acidspearhead step, operators typically use 10% to 15% hydrochloric acid,most preferred being 15% hydrochloric acid due to the highly reactivenature of the acid reducing the time required to initiate the preferredfeed rate. A spearhead acid's purpose is to clear debris that is presentin the wellbore perforations and assists in initiating the next stage ofthe fracture treatment at lower pressures providing a clear pathway forfracture fluids to access the formation. In the second step, the padstep, fluid is injected into the wellbore to break or fracture theformation and initiate the hydraulic fracturing of the target formation.No proppant is used during this step. In the third step, the proppantstep, a mixture of water and proppant (most commonly natural sand orhigh strength synthetic proppant) is injected into the wellbore. Theproppant is carried by the gelled or viscous fluid (also referred to asfracking fluid) into the formation and deposited. The proppant remainsin the formation to maintain the fractures open while the pressure isreduced and fluid and excess proppant is removed from the formation. Theproppant remaining in formation allows the formation to maintain its newincreased permeability. Lastly, the flush step involves the injection ofa large volume of fresh water to be pumped down the wellbore to flushout the leftover excess proppant which could still be residing withinthe wellbore.

Several operations in the oil industry expose fluids to very hightemperatures (some up to and over 190° C.), the compositions used inthese various operations need to withstand high temperatures withoutlosing their overall effectiveness. These compositions must also becapable of being applied in operations over a wide range of temperatureswhile not or at least minimally affecting or corroding the equipmentwith which it comes in contact in comparison to a conventional mineralacid of which the corrosion effect at ultra-high temperatures is verydifficult and expensive to control.

Many countries bordering the waters where offshore drilling andproduction is routinely carried out have put into play a number ofregulations and operational parameters aimed at minimizing theenvironmental and human exposure impact. These regulations/proceduresinclude the ban and/or regulation of certain chemicals which may beharmful to marine life and/or the environment. In order to overcomethese very restrictive regulations, many oil companies employ verycostly containment programs for the handling of certain chemicals, suchas acids, which have a wide array of uses in the industry of oil and gasexploration and production.

Acids conventionally used in various oil and gas operations can beexposed to temperatures of up to and over 190° C. At these temperatures,their reactivity and corrosive properties is exponentially increased andas such their economical effectiveness is greatly decreased. Corrosionis one of the major concerns at high temperatures and is difficult andexpensive to control with additional chemistry, if it can be controlledat all. In some situations, a mechanical procedure must be utilized asopposed to a chemical solution due to temperature constraints or veryexpensive, exotic acid systems not widely available in the marketplace.

Modified and synthetic acids developed and currently patented such asthose containing main components of urea and hydrochloric acid are aimedat increasing personnel safety, reducing corrosion effects, slowing downthe reaction rate and reducing the toxicity of HCl. However, it has beenfound that at temperatures above 90-100° C. the urea component in asynthetic or modified acid containing such compound tends to ultimatelydecompose and produce ammonia and carbon dioxide as a by-product ofdecomposition. The ammonia component will neutralize the acidiccomponent of the HCl and render the product non-reactive or neutral.Additionally, there is the risk of wellbore and/or formation damage dueto uncontrolled, previously solubilized mineral precipitation due to theincrease in pH caused predominantly by the formation of ammonia duringthe decomposition phase.

US 20160032176 A1 discloses methods for treating subterranean wells inwhich the producing formation is a carbonate comprise preparing atreatment fluid comprising either: (a) an aqueous solution of amultivalent-cation reacting polymer; (b) a solution comprising a fattyacid and an ethanolamine; (c) an aqueous acidic solution of one or morecompounds whose calcium salts are insoluble; or (d) an aqueous solutioncomprising urea or alkane derivatives thereof or both andpolyvinylpyrrolidone (PVP). It states that the treatment fluid is placedin the well such that the solution contacts the carbonate formation at apressure lower than the fracturing pressure. It further states that thetreatment fluid is allowed to react with the carbonate formation,thereby depositing a film onto the formation surface or part of theformation surface. Then an acid solution is placed in the well such thatthe acid contacts the carbonate formation at a pressure lower than thefracturing pressure.

Despite the prior art and in light of the substantial challengeselicited by the use of acids in oil and gas operations at hightemperatures, there still exists a critical need to find an alternativeto known synthetic or complexed/modified acids which will remain stableabove temperatures of 90-100° C. while still providing the safety andlower corrosion effects of a modified acid and having a performancecomparable to that of a conventional acid such as HCl. The inventorshave surprisingly and unexpectedly found that by combining analkanolamine with hydrochloric acid in appropriate ratios one can obtainboth a safer alternative to this popular conventional mineral acid(HCl), all the while substantially maintaining the performanceproperties of the acid thereby remaining useful in oil and gasoperations and being competitively priced and widely available.

Consequently, there is still a need for safer, more technically advancedstrong acid compositions for use in various oil industry applicationsand temperatures and which can decrease/minimize or eliminate a numberof the associated dangers and/or operational issues, such as highcorrosion rates and/or safety but not necessarily limited thereto.

It was discovered that the compositions according to the presentinvention exhibit stability for operations at elevated temperature(above 90° C. and up to 190° C.) and therefore makes them useful in theoil and gas industry for all applications where an acid is required andprovides operators the ability to treat high temperature completions andmaintenance/production operations with a technology that provides alevel of safety, technical advantages and low corrosion the combinationof which is rare or unknown in the industry until now. The compositionaccording to the present invention can ideally be used in oilfieldoperations, including but not limited to: spearhead breakdown acid, acidfracturing operations, injection-disposal well treatments, hightemperature cyclical steam injection (CSS) scale treatments, steamassisted gravity drainage (SAGD) scale treatments, surface andsubsurface equipment and pipelines & facilities scale treatments, filtercake treatments, tubing or metal pickling, matrix acidizing operations,stimulations, fracturing, soaks, cement squeezes, fluid pH control,stuck pipe operations, and coiled tubing acid washes, soaks andsqueezes. The most preferred use of a composition according to thepresent invention is for spearhead acid, remedial work and hightemperature cyclical steam and SAGD scale treatments.

SUMMARY OF THE INVENTION

Compositions according to the present invention have been developed forthe oil & gas industry and its associated applications, by targeting theproblems of corrosion, logistics & handling, human & environmentalexposure, reaction rates, toxicity levels, biodegradation tendencies andformation/fluid compatibilities and facility and/or production and watertreatment infrastructure operational compatibilities.

It is an object of the present invention to provide a modified acidcomposition which can be used over a broad range of applications in theoil and gas industry and which exhibit advantageous properties overknown compositions. According to an aspect of the present invention,there is provided a modified acid composition comprising: a strong acidand an alkanolamine in a molar ratio of not more than 15:1; preferablyin a molar ratio not more than 10:1, more preferably in a molar ratio ofnot more than 8:1; even more preferably in a molar ratio of not morethan 5:1; yet even more preferably in a molar ratio of not more than4.1:1; and yet even more preferably in a molar ratio of not more than3:1. According to another aspect of the present invention, there isprovided a modified acid composition comprising: a strong acid and analkanolamine in a molar ratio ranging from 3:1 to 15:1, preferably from3:1 to 10:1; more preferably from 4:1 to 8:1, also preferably from 5:1to 6.5:1.

Preferred embodiments of the present invention provide a modified acidcomposition which, upon proper use, results in a very low corrosion rateon oil and gas industry tubulars down-hole tools and equipment.

According to a preferred of the present invention, there is provided amodified acid composition for use in the oil industry which isbiodegradable. According to a preferred of the present invention, thereis provided a modified acid composition for use in the oil industrywhich will provide a thermal stability at temperatures above 90° C. andup to 190° C.

According to a preferred embodiment of the present invention, there isprovided an aqueous modified acid composition for use in the oilindustry which affords corrosion protection at an acceptable oilfieldlimit at temperatures ranging up to 190° C.

According to a preferred embodiment of the present invention, there isprovided an aqueous modified acid composition for use in the oilindustry which has minimal exothermic reactivity upon dilution or duringthe dilution process with water.

According to a preferred embodiment of the present invention, there isprovided an aqueous modified acid composition for use in the oilindustry which is compatible with existing industry acid additives.

According to a preferred embodiment of the present invention, there isprovided an aqueous modified acid composition for use in oil industryoperations which is immediately reactive upon contact/application withcalcium-based sale or formations.

According to a preferred of the present invention, there is provided anaqueous modified acid composition for use in the oil industry whichresults in less unintended near wellbore erosion or face dissolution dueto a more controlled hydrogen proton donation. This, in turn, results indeeper, more optimal formation penetration and worm-holing properties,increased permeability, and reduces the potential for zonalcommunication during a typical ‘open hole’ mechanical isolationapplication treatment. When a highly reactive acid, such as hydrochloricacid, is deployed into a well that has open hole packers for isolation(without casing) there is a potential to cause a loss of near-wellborecompressive strength resulting in communication between zones orsections of interest as well as potential sand production, and finesmigration. In addition, conventional mineral acids commonly deployedsuch as hydrochloric acid can cause wellbore stability issues, due totheir highly reactive nature, resulting in the potential for compressiveforces to be greatly increased thereby causing potential expensiveremedial work due to collapsed or compressed production tubulars. It isadvantageous to have a modified acid with an increased activation energybarrier or more controlled proton diffusion coefficient.

Accordingly, a preferred embodiment of the present invention wouldovercome at least several of the drawbacks found in the use ofconventional acid compositions of the prior art related to the oil & gasindustry.

According to another aspect of the present invention, the modified acidcomposition can also be used in the mining industry for the usesselected from the group consisting of: treating scale and adjusting pHlevels in fluid systems. According to yet another aspect of the presentinvention, the modified acid composition can also be used in the watertreatment industry said use being selected from the group consisting of:adjusting pH and neutralizing alkaline effluent. According to yetanother aspect of the present invention, the modified acid compositioncan also be used in the fertilizer/landscaping industry to adjust the pHlevel of a soil. According to yet another aspect of the presentinvention, the modified acid composition can also be used to regenerateion exchange beds. According to yet another aspect of the presentinvention, the modified acid composition can also be used in theconstruction industry said use being selected from the group consistingof: etching concrete and cleaning concrete from equipment and buildings.According to yet another aspect of the present invention, the modifiedacid composition can also be used in the electrical generation industry,said use being selected from the group consisting of: descalingpipelines and related equipment and descaling facilities. According toyet another aspect of the present invention, the modified acidcomposition can also be used in the food and dairy industry, said usebeing selected from the group consisting of: manufacturing protein,manufacturing starch, demineralizing whey, manufacturing casein andregenerating ion exchange resins. According to yet another aspect of thepresent invention, the modified acid composition can also be used in thein the pool industry to lower the pH of fluids. According to yet anotheraspect of the present invention, the modified acid composition can alsobe used in the manufacturing industry to perform an operation selectedfrom the group consisting of: pickling steel and cleaning metal.According to yet another aspect of the present invention, the modifiedacid composition can also be used in the retail industry as a low pHcleaning additive.

BRIEF DESCRIPTION OF THE FIGURES

The invention may be more completely understood in consideration of thefollowing description of various embodiments of the invention inconnection with the accompanying figure, in which:

FIG. 1 is a graphical representation of the spend rate of variousconcentrations of a preferred embodiment according to the presentinvention versus two concentrations of a control composition;

FIG. 2 is a graphical representation of the spend/reaction rate ofvarious concentrations of another preferred embodiment according to thepresent invention versus two concentrations of a control composition;

FIG. 3 is a CT scan of various wormholes obtained as a function of theinjection of acid (acid flux) into a formation;

FIG. 4 is a graphical representation of the results of the wormholeefficiency relationship testing using a composition according to apreferred embodiment of the present invention;

FIGS. 5A, 5B, 5C, 5D and 5E are images of the wormholes obtained duringthe wormhole efficiency relationship testing using a compositionaccording to a preferred embodiment of the present invention;

FIG. 6 is a graphical representation of the skin evolution overinjection volume for HCl (15%) and the composition of Example 1 (90%conc.);

FIG. 7 is a graphical representation of the stimulated productivityindex over time for HCl (15%) and the composition of Example 1 (90%conc.);

FIG. 8 is a graphical representation of the wormhole penetration lengthover total injection volume for HCl (15%) and the composition of Example1 (90% conc.);

FIG. 9 is a graphical representation of the productivity indexcomparison at 0 skin for HCl (15%) and the composition of Example 1 (90%conc.); and

FIG. 10 is a graphical representation of the productivity indexcomparison at 10 skins for HCl (15%) and the composition of Example 1(90% conc.).

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The description that follows, and the embodiments described therein, isprovided by way of illustration of an example, or examples, ofparticular embodiments of the principles of the present invention. Theseexamples are provided for the purposes of explanation, and notlimitation, of those principles and of the invention.

According to an aspect of the present invention, there is provided asynthetic or modified acid composition comprising:

-   -   a strong acid and an alkanolamine in a molar ratio of not more        than 15:1; preferably in a molar ratio not more than 10:1, more        preferably in a molar ratio of not more than 8:1; even more        preferably in a molar ratio of not more than 5:1; yet even more        preferably in a molar ratio of not more than 4.1:1; and yet even        more preferably in a molar ratio of not less than 3:1.

Preferably, the main components in terms of volume and weight percent ofthe composition of the present invention comprise an alkanolamine and astrong acid, such as HCl, nitric acid, phosphoric acid, sulfuric acid,sulfonic acid. An alkanolamine according to the present inventioncontains at least one amino group, —NH₂, and one alcohol group, —OH.Preferred alkanolamines according to the present invention include, butare not limited to, monoethanolamine, diethanolamine andtriethanolamine. More preferred are monoethanolamine, diethanolamine.Most preferred is monoethanolamine. When added to hydrochloric acid aLewis acid/base adduct is formed where the primary amino group acts as aLewis base and the proton of the HCl as Lewis acid. The formed adductgreatly reduces the hazardous effects of the hydrochloric acid on itsown, such as the fuming/vapor pressure effect, the hygroscopicity, andthe highly corrosive nature. Various organic acids are also contemplatedaccording to a preferred embodiment of the present invention.

The molar ratio of the two main components can be adjusted or determineddepending on the intended application and the desired solubilizingability. While a molar ratio of HCl:MEA of 1:1 can be used, results aresignificantly optimized when working above a 2:1 ratio and preferablyabove a 3:1 ratio. According to a preferred embodiment where the strongacid is HCl, one can increase the ratio of the HCl component to increasethe solubilizing ability of the composition while still providing atleast one of the following advantages: health; safety; environmental;and operational advantages over hydrochloric acid.

While an alkanolamine such as monoethanolamine is a compound known bythe person of ordinary skill in the art, the latter knows that such acompound is not to be mixed with a strong acid such as HCl. In fact, theperson skilled in the art will note upon review of the DOW safety datasheet for monoethanolamine LFG 85 that it indicates that one must avoidcontact of this compound with strong acids.

Various corrosion inhibitors can be incorporated into a preferredcomposition of the present invention which comprises a strong acid andan alkanolamine to reduce corrosion on the steel which is contacted bythe composition according to the present invention. According to apreferred embodiment of the present invention, the composition mayfurther comprise organic compounds which may act as corrosion inhibitorsselected from the group consisting of: acetylenic alcohols, aromatic oraliphatic aldehydes (e.g. α,β-unsaturated aldehydes), alkylphenones,amines, amides, nitrogen-containing heterocycles (e.g.imidazoline-based), iminium salts, triazoles, pyridine and itsderivatives or salts, quinoline derivatives, thiourea derivatives,thiosemicarbazides, thiocyanates, quaternary amine salts, andcondensation products of carbonyls and amines. Intensifiers which can beincorporated into compositions according to the present invention areselected from the group consisting of: formic acid, potassium iodide,antimony oxide, copper iodide, sodium iodide, lithium iodide, aluminiumchloride, bismuth oxide, calcium chloride, magnesium chloride andcombinations of these. Preferably, an iodide compound such as potassiumiodide is used.

Other additives can be optionally added to a composition according to apreferred embodiment of the present invention. A non-limiting list ofsuch common additives includes iron control agents (e.g. reducingagents), water-wetting surfactants, non-emulsifiers, de-emulsifiers,foaming agents, antisludging agents, clay and/or fines stabilizer, scaleinhibitors, mutual solvents, friction reducer.

Alcohols and derivatives thereof, such as alkyne alcohols andderivatives and preferably propargyl alcohol and derivatives thereof canbe used as corrosion inhibitors. Propargyl alcohol itself istraditionally used as a corrosion inhibitor which works well at lowconcentrations. It is however a very toxic/flammable chemical to handleas a concentrate, so care must be taken when exposed to the concentrate.In the composition according to the present invention, it is preferredto use 2-Propyn-1-ol, complexed with methyloxirane, as this is a muchsafer derivative to handle. Basocorr® PP is an example of such acompound.

Metal iodides or iodates such as potassium iodide, sodium iodide,cuprous iodide and lithium iodide can potentially be used as corrosioninhibitor intensifier along with the composition according to preferredembodiments of the present invention. In fact, potassium iodide is ametal iodide traditionally used as corrosion inhibitor intensifier,however it is expensive, but works extremely well. It is non-regulatedand safe to handle. The iodide or iodate is preferably present in aweight percentage ranging from 0.1 to 5 wt %, more preferably from 0.2to 3 wt %, yet even more preferably from 0.25 to 2 wt %.

Example 1—Process to Prepare a Composition According to a PreferredEmbodiment of the Invention

Monoethanolamine (MEA) and hydrochloric acid are used as startingreagents. To obtain a 4.1:1 molar ratio of MEA to HCl, one must firstmix 165 g of MEA with 835 g of water. This forms the monoethanolaminesolution. Subsequently, one takes 370 ml of the previously preparedmonoethanolamine solution and mixes with 350 ml of HCl aq. 36% (22Baume). In the event that additives are used, they are added afterthorough mixing of the MEA solution and HCl. For example, potassiumiodide can be added at this point as well as any other component desiredto optimize the performance of the composition according to the presentinvention. Circulation is maintained until all products have beensolubilized. Additional products can now be added as required.

The resulting composition of Example 1 is a clear (slightly yellow)liquid having shelf-life of greater than 1 year. It has a boiling pointtemperature of approximately 100° C. It has a specific gravity of1.1±0.02. It is completely soluble in water and its pH is less than 1.The freezing point was determined to be less than −35° C.

The organic component in the composition is biodegradable. Thecomposition is classified as a mild irritant according to theclassifications for skin tests. The composition is substantially lowerfuming compared to 15% HCl. Toxicity testing was calculated usingsurrogate information and the LD₅₀ was determined to be greater than−1300 mg/kg.

TABLE 1 Content of preferred embodiments of compositions of Examples 1,2 and 3 Example 1 Example 2 Example 3 MEA:HCl MEA-HCl MEA-HCl 1:4.1molar ratio 1:6.4 molar ratio 1:9.9 molar ratio 165 g MEA 165 g MEA 165g MEA 835 g Water 835 g Water 835 g Water ==> MEA mixture ==> MEAmixture ==> MEA mixture 370 ml of the MEA 370 ml of the MEA 370 ml ofthe MEA mixture + 350 ml mixture + 550 ml mixture + 850 ml HCl 22 BaumeHCl 22 Baume HCl 22 Baume

The content of HCl in the composition of Example 1 corresponds to thecontent of HCl in a 15% HCl composition. Similarly, Example 2corresponds to the content of HCl in a 20% HCl composition. As well,Example 3 corresponds to the content of HCl in a 25% HCl composition.

TABLE 2 Properties of prepared compositions according to preferredembodiments of the present invention MEA:HCl MEA:HCl MEA:HCl 1:4.1 molarratio 1:6.4 molar ratio 1:9.9 molar ratio 100% 100% 100% AppearanceTransparent, Transparent, Transparent, slight yellow slight yellowslight yellow Specific Gravity at 1.1 1.121 1.135 23° C. Salinity, %31.20% 36.80% 40.00 Odor slight sharp sharp sharp Boiling Point 100° C.100° C. 100° C. Freezing Point −35° C. −35° C. −35° C. Acid Strength, ml4.9 6.3 7.5 1N NaOH pH −0.11 −0.41 −0.73

According to a preferred embodiment of the present invention, thecomposition comprising an alkanolamine and a strong acid may furthercomprise a corrosion inhibition package itself comprising a terpene; aα,β-unsaturated aldehyde with no methyl group at the alpha position; atleast one amphoteric surfactant; and a solvent. Preferably, theα,β-unsaturated aldehyde with no methyl group at the alpha position canbe used, examples of such aldehydes include but are not limited tocitral and cinnamaldehyde (and derivatives thereof). These componentsare preferably present in an amount ranging from 0.025 to 0.5% in thefinal modified acid composition.

In other preferred embodiments of the present invention, 2-Propyn-1-ol,complexed with methyloxirane can be present in a range of 0.05-5.0 wt/wt%, preferably it is present in an amount ranging from 0.1 to 3 wt %,even more preferably from 0.5 to 2.0 wt/wt % and yet even morepreferably from 0.75 to 1.5 wt/wt %. As a substitute for potassiumiodide one could use sodium iodide, copper iodide and lithium iodide.However, potassium iodide is the most preferred.

According to a preferred embodiment of the present invention thecorrosion package may comprise terpene compounds. The terpenesconsidered by the inventors to achieve desirable corrosion inhibitionresults comprise: monoterpenes (acyclic); monocyclic terpenes; andbeta-Ionone. Exemplary but non-limiting compounds of some of thepreviously listed terpene sub-classes comprise: for monoterpenes: citral(mixture of geranial and neral); citronellal; geraniol; and ocimene; formonocyclic terpenes: alpha-terpinene; carvone; p-cymene. Morepreferably, the terpenes are selected from the group consisting of:citral; ionone; ocimene; and cymene.

It is preferable that the corrosion inhibition package comprises asurfactant which is environmentally friendly. More preferably, thesurfactant is capable of withstanding exposure to temperatures of up toleast 220° C. for a duration of 2 to 4 hours in a closed environmentwithout undergoing degradation.

Preferably, surfactants which are amhoteric are present in the corrosioninhibition package. Preferably, the amphoteric surfactant is selectedfrom the group consisting of: a sultaine surfactant; a betainesurfactant; and combinations thereof. More preferably, the sultainesurfactant and betaine surfactant are selected from the group consistingof: an amido betaine surfactant; an amido sultaine surfactant; andcombinations thereof. Yet even more preferably, the amido betainesurfactant and is selected from the group consisting of: an amidobetaine comprising a hydrophobic tail from C₈ to C₁₆. Most preferably,the amido betaine comprising a hydrophobic tail from C₈ to C₁₆ iscocamidobetaine.

Preferably also, the corrosion inhibition package further comprises ananionic surfactant. Preferably, the anionic surfactant is a carboxylicsurfactant. More preferably, the carboxylic surfactant is a dicarboxylicsurfactant. Even more preferably, the dicarboxylic surfactant comprisesa hydrophobic tail ranging from C₈ to C₁₆. Most preferably, thedicarboxylic surfactant is sodium lauriminodipropionate.

Some preferred embodiments use corrosion inhibition package comprisingcocamidopropyl betaine and ß-Alanine, N-(2-carboxyethyl)-N-dodecyl-,sodium salt (1:1).

According to a preferred embodiment of the present invention, whenpreparing an acidic composition comprising a corrosion inhibitionpackage, metal iodides or iodates such as potassium iodide, sodiumiodide, cuprous iodide and lithium iodide can be added as corrosioninhibitor intensifier. The iodide or iodate is preferably present in aweight/volume percentage ranging from 0.1 to 1.5%, more preferably from0.25 to 1.25%, yet even more preferably 1% by weight/volume of theacidic composition. Most preferably, the iodide used is potassiumiodide.

Preferably, the terpene is present in an amount ranging from 2% to 25%by volume of the total volume of the corrosion inhibition package.

According to a preferred embodiment, when present, the propargyl alcoholor derivative thereof is present in an amount ranging from 20% to 55% byvolume of the total volume of the corrosion inhibition package.

Preferably, the at least one surfactant is present in an amount rangingfrom 2% to 20% by volume of the total volume of the corrosion inhibitionpackage.

Preferably, the solvent is present in an amount ranging from 10% to 45%by volume of the total volume of the corrosion inhibition package.

According to a preferred embodiment of the present invention, thecorrosion package comprises: 2-Propyn-1-ol, compd. with methyloxirane;ß-Alanine, N-(2-carboxyethyl)-N-dodecyl-, sodium salt (1:1);cocamidopropyl betaine; (±)-3,7-Dimethyl-2,6-octadienal (Citral); andisopropanol. More preferably, the composition comprises 38.5% of2-Propyn-1-ol, compd. with methyloxirane; 5% of ß-Alanine,N-(2-carboxyethyl)-N-dodecyl-, sodium salt (1:1); 5% of cocamidopropylbetaine; 20% of (±)-3,7-Dimethyl-2,6-octadienal (Citral); and 31.5% ofisopropanol (all percentages are volume percentages).

When used with a composition according to a preferred embodiment of thepresent invention, citral is present in a concentration ranging from 5to 30 vol % of the total volume of the corrosion inhibition package;cinnamaldehyde can be present in a concentration ranging from 5 to 30vol %; and cocamidobetaine can be present in a concentration rangingfrom 2.5 to 15 vol %. Depending on various factors, such as temperature,acid, metal, etc. preferred corrosion inhibitor package loadings withinthe acid compositions can range between 0.1 to 7.5% vol/vol. Morepreferably, between 0.1 and 5% vol/vol. Various biodegradation, toxicityand bioaccumulation testing carried out have indicated that most of thecompositions using those components have been identified assatisfactorily meeting the requirements for listing under aclassification of Yellow for offshore use in the North Sea (Norway).

Corrosion Testing

Compositions according to preferred embodiments of the present inventionwere exposed to corrosion testing. In most cases, corrosion packageswere added to the various acid fluids. The % of the corrosion packagecomponent indicates its % within the final blended composition(acid+corrosion inhibitor). The results of the corrosion tests arereported in Tables 3 through 25. The controls used were compositions ofHCl. Coupons of various steel grades were exposed to the various listedcompositions for various periods of time at varying temperatures. Apreferable result is one where the lb/ft2 corrosion number is at orbelow 0.05. More preferably, that number is at or below 0.02.

TABLE 3 Corrosion testing comparison between MEA-HCl using noadditive-run time of 6 hours on 1018 steel coupons at a temperature of110° C. having a surface area of 41.4 cm² (coupon density of 7.86 g/cc)Initial Final Loss Run Temp Corrosion Wt. wt. wt. Time Fluid ° C.Package (g) (g) (g) (hours) Mils/yr mm/year lb/ft2 15% 110 none 74.14348.421 25.722 6 45436.180 1154.079 1.273 HCl Example 110 none 74.18162.579 11.603 6 20495.131 520.576 0.574 diluted to 50%

TABLE 4 Corrosion testing comparison between MEA-HCl using variousadditives-run time varying between 2 and 6 hours on L-80 steel couponsat various temperatures having a surface area of 28.0774 cm² (coupondensity of 7.86 g/cc) Fluid Temp Corrosion Loss wt. Run Mils/yr mm/yearlb/ft2 Example 1 130  2.0% CI-5 0.194 6 504.248 12.808 0.014 Example 1130  3.0% CI-5 0.276 6 718.345 18.246 0.020 Example 1 150  2.0% CI-50.243 4 950.544 24.144 0.018 Example 1 150  3.0% CI-5 0.231 4 903.661422.953 0.017 Example 1 200  7.5% CI-5 0.355 2 2775.448 70.496 0.026Example 1 110 1.75% CI-5 0.077 6 200.0323 5.081 0.006

-   -   The dilution of the fluid is done by using the concentrate        (Example 1) composition and diluting with tap water to half the        original concentration.    -   CI-1A refers to potassium iodide; CI-5 refers to a proprietary        corrosion inhibitor package comprising a terpene; a        cinnamaldehyde or a derivative thereof; at least one amphoteric        surfactant; and a solvent.

TABLE 5 Corrosion testing comparison between MEA-HCl and DEA-HCl usingvarious additives-run time varying between 2 and 6 hours on varioussteel coupons at a temperature of 110° C. having a surface area of28.0774 cm² (coupon density of 7.86 g/cc) Initial Final Loss RunCorrosion Wt. wt. wt. Time Steel Fluid Package (g) (g) (g) (hr) Mils/yrmm/year lb/ft2 N80 Example 1.75% 61.24 61.137 0.108 6 281.555 7.152 0.00L80 50% 1.75% 60.55 60.3834 0.167 4 651.667 16.552 0.01 N80 50% 1.75%60.34 60.236 0.106 4 414.52 10.529 0.00

TABLE 6 Corrosion testing comparison between MEA-HCl using variousadditives-run time of 6 hours on 1018 steel coupons at a temperature of90° C. having a surface area of 41.4 cm² (coupon density of 7.86 g/cc)Initial Final Loss Corrosion Wt. wt. wt. Fluid Package (g) (g) (g)Mils/yr mm/year lb/ft2 Example 1 0.75% CI-5, 74.1448 74.0485 0.096170.1068 4.321 0.005 diluted to 0.25% CI-1A 50% 50% 0.75% CI-5, 74.22474.1375 0.087 152.7958 3.881 0.004 DEA:HCl 0.25% CI-1A 1:4.1 Example 1None 74.1723 65.8583 8.314 14686.06 373.026 0.411 diluted to 50% Example1 0.25% CI-5, 74.0726 73.4539 0.619 1092.888 27.759 0.031 diluted to0.15% CI-1A 50% Example 1 0.50% CI-5, 74.1381 73.744 0.394 696.148417.682 0.019 diluted to 0.15% CI-1A 50% Example 2 None 74.0655 61.983612.082 21341.78 542.081 0.598 diluted to 50% Example 2 0.25% CI-5,74.1492 71.8392 2.310 4080.443 103.643 0.114 diluted to 0.15% CI-1A 50%Example 2 0.50% CI- 5, 74.1115 73.6647 0.447 789.239 20.047 0.022diluted to 0.15% CI-1A 50% Example 3 None 74.1601 59.278 14.882 26288.12667.718 0.736 diluted to 50% Example 3 0.25% CI-5, 74.153 70.3044 3.8496798.266 172.676 0.190 diluted to 0.15% CI-1A 50% Example 3 0.50% CI-5,74.1107 73.3095 0.801 1415.26 35.948 0.040 diluted to 0.15% CI-1A 50%

TABLE 7 Corrosion testing comparison between MEA-HCl using variousadditives-run time of 6 hours on L80 steel coupons at a temperature of120° C. having a surface area of 41.4 cm² (coupon density of 7.86 g/cc)Initial Final Loss Corrosion Wt. wt. wt. Fluid Package (g) (g) (g)Mils/yr mm/year lb/ft2 Example 1 0.75% CI-5, 59.8578 59.564 0.294518.9759 13.182 0.015 diluted to 50% 0.50% CI-1A Example 1  1.0% CI-5,60.2693 59.9396 0.330 582.3906 14.793 0.016 diluted to 50% 0.75% CI-1AExample 1 1.25% CI-5, 60.4076 59.5108 0.897 1584.131 40.237 0.044diluted to 50% 0.75% CI-1A

TABLE 8 Corrosion testing comparison between MEA-HCl using variousadditives-run time of 6 hours on 1018 steel coupons at a temperature of90 C. having a surface area of 41.4 cm² (coupon density of 7.86 g/cc)Initial Final Loss Corrosion Wt. wt. wt. Fluid Package (g) (g) (g)Mils/yr mm/year lb/ft2 Example 0.60% CI-5 74.0052 73.7828 0.222 392.85319.978 0.011 1 diluted 0.25% CI-1A to 50% Example 0.50% CI-5, 74.115173.823 0.292 515.973 13.106 0.014 1 diluted 0.25% CI-1A to 50% Example0.60% CI-5 74.0215 73.8259 0.196 345.5129 8.776 0.010 2 diluted 0.25%CI-1A to 50% Example 0.50% CI-5 74.063 73.7148 0.348 615.0694 15.6230.017 2 diluted 0.25% CI-1A to 50% Example 0.60% CI-5 74.0873 73.50280.585 1032.476 26.225 0.029 3 diluted 0.25% CI-1A to 50% Example 0.50%CI-5 74.0916 73.51 0.582 1027.353 26.095 0.029 3 diluted 0.25% CI-1A to50%

TABLE 9 Corrosion testing comparison between MEA-HCl using variousadditives-varying run times on various steel coupons at varioustemperature (coupon density of 7.86 g/cc) Temp Run Corrosion SurfaceCoupon Fluid ° C. time Package area Mils/yr Mm/year Lb/ft2 N80 Example 1 90 6   0.6% CI-5 28.0774 240.403 6.106 0.007 (50%  0.025% CI-1Adilution) J55 Example 1  90 6   0.6% CI-5 28.922 138.310 3.513 0.004(50%  0.025% CI-1A dilution) P110 Example 1  90 4   0.6% CI-5 28.922364.487 9.258 0.007 (50%  0.025% CI-1A dilution) QT900 Example 1  90 6  0.6% CI-5 34.31 93.784 2.382 0.003 (50%  0.025% CI-1A dilution) N80Example 1 110 6  0.75% CI-5 28.0774 396.418 10.069 0.011 (50%  0.050%CI-1A dilution) J55 Example 1 110 6  0.75% CI-5 28.922 144.632 3.6740.004 (50%  0.050% CI-1A dilution) P110 Example 1 110 4  0.75% CI-528.922 701.287 17.813 0.013 (50%  0.050% CI-1A dilution) QT900 Example 1110 6  0.75% CI-5 34.31 339.966 8.635 0.010 (50%  0.050% CI-1A dilution)1018 Example 1 110 6  0.75% CI-5 33.22 313.9176 7.974 0.009 (50%  0.050%CI-1A dilution) L80 Example 1  90 6   0.6% CI-5 28.0774 278.170 7.0660.008 (dilution to  0.025% CI-1A 33% of stock   0.1% NE-1 solution) L80Example 1 120 6   0.6% CI-5 28.0774 1773.724 45.053 0.050 (dilution to 0.025% CI-1A 33% of stock   0.1% NE-1* solution) L80 Example 1 120 6 0.75% CI-5 28.0774 798.566 20.284 0.022 (dilution to  0.05% CI-1A 33%of stock   0.1% NE-1 solution) P110 Example 1 120 6  0.925% CI-5 28.9221398.528 35.523 0.040 (dilution to 0.0625% CI-1A 33% of stock   0.1%NE-1 solution) P110 Example 1 120 6  1.25% CI-5 28.922 834.161 21.1880.024 (dilution to  0.095% CI-1A 33% of stock   0.1% NE-1 solution)

TABLE 10 Corrosion testing of various MEA-HCl compositions using variousadditives—varying run times on various steel coupons at varioustemperatures (coupon density of 7.86 g/cc) Temp Run time CorrosionSurface Coupon Fluid ° C. (hours) Package area (cm²) Mils/yr Mm/yearLb/ft² P110 Example 90 72 1% CI-5 28.922 66.648 1.693 0.023 2 (50% 0.1%CI- dilution) 1A P110 Example 90 72 2% CI-5 28.922 36.832 0.936 0.013 2(50% 0.2% CI- dilution) 1A P110 Example 90 72 3% CI-5 28.922 34.9570.888 0.012 2 (50% 0.3% CI- dilution) 1A P110 Example 90 168 2% CI-528.922 38.063 0.967 0.031 2 (50% 0.2% CI- dilution) 1A P110 Example 90168 3% CI-5 28.922 33.431 0.849 0.027 2 (50% 0.3% CI- dilution) 1A N80Example 60 6 0.25% CI-5 28.0774 123.197 3.129 0.003 1 (50% dilution) 155 Example 60 6 0.25% CI-5 28.922 79.901 2.029 0.002 1 (50% dilution)1018 Example 60 6 0.25% CI-5 33.22 431.472 10.959 0.012 1 (50% dilution)J55 Example 130 6 1.75% CI-5 28.922 515.314 13.089 0.014 1 (50% 0.125%CI- dilution) 1A 1018 Example 130 6 1.75% CI-5 33.22 1371.683 34.8410.038 1 (50% 0.125% CI- dilution) 1A N80 Example 130 6 2.25% CI-528.0774 1671.884 42.466 0.047 1 (50% 0.175% CI- dilution) 1A 1018Example 130 6 2.25% CI-5 33.22 1289.351 32.750 0.036 1 (50% 0.175% CI-dilution) 1A N80 Example 150 4 2.25% CI-5 28.0774 1498.679 38.066 0.0281 (50% 0.225% CI- dilution) 1A N80 Example 150 4 2.50% CI-5 28.07741058.374 26.883 0.020 1 (50% 0.275% CI- dilution) 1A

TABLE 11 Corrosion testing of the composition of Example 1 (diluted to50%) using various concentrations of the same additives—varying runtimes on L80 steel coupons at a temperature of 150° C. or 170° C.(coupon density of 7.86 g/cc) (coupon surface area of 28.0774 cm²) RunTemp time Corrosion Fluid ° C. (hours) Package Mils/yr Mm/year Lb/ft²Example 1 150 4 2.0% CI-5  752.4651268 19.113 0.014 (50% 0.25% CI-dilution) 1A Example 1 150 4 2.5% CI-5  553.6049245 14.062 0.010 (50%0.25% CI- dilution) 1A Example 1 170 3 7.5% CI-5 2690.017248 68.3260.038 (50% 0.75% CI- dilution) 1A

TABLE 12 Corrosion testing of various MEA-HCl compositions using variousadditives—varying run times on L80 steel coupons at a temperature of120° C. (coupon density of 7.86 g/cc) (coupon surface area of 28.0774cm²) Run time Corrosion Fluid (hours) Package Mils/yr Mm/year Lb/ft2Example 1 3  0.5% CI-5 492.2669054 12.504 0.007 (50% 0.25% CI-1Adilution) Example 1 3 0.75% CI-5 557.9024928 14.171 0.008 (50%  0.5%CI-1A dilution) Example 2 3  0.5% CI-5 797.5244785 20.257 0.011(dilution to 0.25% CI-1A 33% of stock solution) Example 2 3 0.75% CI-5434.9659958 11.048 0.006 (dilution to  0.5% CI-1A 33% of stock solution)Example 1 3  0.5% CI-5 502.6852526 12.768 0.007 (dilution to 0.25% CI-1A33% of stock solution) Example 1 4  0.5% CI-5 544.2284121 13.823 0.010(dilution to 0.25% CI-1A 33% of stock solution) Example 1 5  0.5% CI-51210.820312 30.755 0.028 (dilution to 0.25% CI-1A 33% of stock solution)Example 1 4  0.5% CI-5 566.4976292 14.389 0.011 (50% 0.25% CI-1Adilution) Example 1 5  0.5% CI-5 984.5338108 25.007 0.023 (50% 0.25%CI-1A dilution)

TABLE 13 Corrosion testing of various MEA-HCl compositions using variousadditives—varying run times on various steel coupons at a temperature of90° C. (coupon density of 7.86 g/cc) Run time Corrosion Surface areaCoupon Fluid (hours) Package (cm²) Mils/yr Mm/year Lb/ft² L80 Example 721.5% CI- 28.0774 59.40628395 1.509 0.020 1 (50% 5 dilution) 0.15% CI-1AP110 Example 72 1.5% CI- 28.922 41.69960594 1.059 0.014 1 (50% 5dilution) 0.15% CI-1A P110 Example 72 2.0% CI- 28.922 38.85501433 0.9870.013 1(50% 5 dilution) 0.2% CI- 1A L80 Example 6 0.5% CI- 28.0774278.6907877 7.079 0.008 2 (50% 5 0.025% dilution) CI-1A N80 Example 60.5% CI- 28.0774 175.028233 4.446 0.005 2 (50% 5 0.025% dilution) CI-1AJ55 Example 6 0.5% CI- 28.922 169.6640864 4.309 0.005 2 (50% 5 0.025%dilution) CI-1A P110 Example 6 0.5% CI- 28.922 214.4189945 5.446 0.006 2(50% 5 0.025% dilution) CI-1A QT-900 Example 6 0.5% CI- 34.3194.21005901 2.393 0.003 2 (50% 5 0.025% dilution) CI-1A 1018CS Example 60.5% CI- 33.22 1000.529698 25.413 0.028 2 (50% 5 0.025% dilution) CI-1A

TABLE 14 Corrosion testing comparison between MEA-HCl using variousadditives—during a 6 hour run time on various steel coupons at atemperature of 110° C. (coupon density of 7.86 g/cc) Corrosion Surfacearea Coupon Fluid Package (cm²) Mils/yr Mm/year Lb/ft² L80 Example 0.75%CI- 28.0774 458.407277 11.644 0.013 2 (50% 5 0.05% dilution) CI-1A N80Example 0.75% CI- 28.0774 460.4909464 11.696 0.013 2 (50% 5 0.05%dilution) CI-1A J55 Example 0.75% CI- 28.922 147.6659113 3.751 0.004 2(50% 5 0.05% dilution) CI-1A P110 Example 0.75% CI- 28.922 249.31265166.333 0.007 2 (50% 5 0.05% dilution) CI-1A QT-900 Example 0.75% CI-34.31 165.4004656 4.201 0.005 2 (50% 5 0.05% dilution) CI-1A 1018CSExample 0.75% CI- 33.22 195.2628915 4.960 0.005 2 (50% 5 0.05% dilution)CI-1A L80 Example 1.0% CI-5 28.0774 616.2452371 15.653 0.017 2 (50%0.075% dilution) CI-1A N80 Example 1.0% CI-5 28.0774 515.9686453 13.1060.014 2 (50% 0.075% dilution) CI-1A P110 Example 1.0% CI-5 28.922297.3546433 7.553 0.008 2 (50% 0.075% dilution) CI-1A

TABLE 15 Corrosion testing comparison between MEA-HCl using variousadditives—varying run times on various steel coupons at varioustemperatures (coupon density of 7.86 g/cc) Run Temp time CorrosionSurface area Coupon Fluid ° C. (hours) Package (cm²) Mils/yr Mm/yearLb/ft² 1018CS Example 40 6 0.5% CI-5 33.22 39.185 0.995 0.001 1 0.025%(dilution CI-1A to 10% 0.1% NE-1 of stock solution) 1018CS Example 40 60.5% CI-5 33.22 37.864 0.962 0.001 1 0.025% (dilution CI-1A to 25% 0.1%NE-1 of stock solution) 1018CS Example 40 6 0.5% CI-5 33.22 39.405 1.0010.001 1 0.025% (dilution CI-1A to 33% 0.1% NE-1 of stock solution)1018CS Example 70 6 0.5% CI-5 33.22 129.441 3.288 0.004 1 0.025%(dilution CI-1A to 10% 0.1% NE-1 of stock solution) 1018CS Example 70 60.5% CI-5 33.22 123.278 3.131 0.003 1 0.025% (dilution CI-1A to 25% 0.1%NE-1 of stock solution) 1018CS Example 70 6 0.5% CI-5 33.22 139.7883.551 0.004 1 0.025% (dilution CI-1A to 33% 0.1% NE-1 of stock solution)L80 Example 150 4 3% CI-5 28.0774 1383.426 35.139 0.026 1 (50% 0.3% CI-dilution) 1A J55 Example 110 6 1.5% CI-6 28.922 227.567 5.780 0.006 10.15% CI- (dilution 1A to 90% of stock solution) J55 Example 110 6 1.25%CI- 28.922 313.790 7.970 0.009 1 6 0.1% (dilution CI-1A to 90% of stocksolution) L80 Example 110 6 1.25% CI- 28.0774 714.178 18.140 0.020 1 60.1% (dilution CI-1A to 90% of stock solution) N80 Example 110 6 1.25%CI- 28.0774 1172.325 29.777 0.033 1 6 0.1% (dilution CI-1A to 90% ofstock solution) P110 Example 110 6 1.25% CI- 28.922 1038.971 26.3900.029 1 6 0.1% (dilution CI-1A to 90% of stock solution) QT-900 Example110 6 1.25% CI- 34.31 663.520 16.853 0.019 1 6 0.1% (dilution CI-1A to90% of stock solution) 1018CS Example 110 6 1.25% CI- 33.22 779.73119.805 0.022 1 6 0.1% (dilution CI-1A to 90% of stock solution) L80-Example 110 3 1.25% CI- 8.47 286.649 7.281 0.004 CR13 1 6 0.1% (dilutionCI-1A to 90% of stock solution) J55 Example 110 6 0.75% CI- 28.922135.276 3.436 0.004 1 5 0.05% (dilution CI-1A to 90% of stock solution)L80 Example 110 6 0.75% CI- 28.0774 201.335 5.114 0.006 1 5 0.05%(dilution CI-1A to 90% of stock solution) N80 Example 110 6 0.75% CI-28.0774 178.154 4.525 0.005 1 5 0.05% (dilution CI-1A to 90% of stocksolution) P110 Example 110 6 0.75% CI- 28.922 189.134 4.804 0.005 1 50.05% (dilution CI-1A to 90% of stock solution) QT-900 Example 110 60.75% CI- 34.31 165.187 4.196 0.005 1 5 0.05% (dilution CI-1A to 90% ofstock solution) QT-800 Example 110 6 0.75% CI- 34.31 135.134 3.432 0.0041 5 0.05% (dilution CI-1A to 90% of stock solution) 1018CS Example 110 60.75% CI- 33.22 270.330 6.866 0.008 1 5 0.05% (dilution CI-1A to 90% ofstock solution) CI-6: is a proprietary corrosion inhibitor comprisingcitral and cinnamaldehyde. CI-4A: propargyl alcohol with methyloxirane

TABLE 16 Corrosion testing comparison between MEA-HCl using variousadditives—varying run times on various steel coupons at a temperature of120° C. (coupon density of 7.86 g/cc) Run time Corrosion Surface areaCoupon Fluid (hours) Package (cm²) Mils/yr Mm/year Lb/ft² P110 Example 60.90% CI-5 28.922 787.8886636 20.012 0.022 1 CNE (diluted to 20% ofstock solution) QT-900 Example 6 0.90% CI-5 34.31 1283.771913 32.6080.036 1 CNE (diluted to 20% of stock solution) P110 Example 6 1.0% CI-528.922 875.6285116 22.241 0.025 1 CNE (diluted to 20% of stock solution)P110 Example 6 1.25% CI-5 28.922 602.5477167 15.305 0.017 1 CNE (dilutedto 20% of stock solution) P110 Example 6 1.5% CI-5 28.922 787.63581120.006 0.022 1 CNE (diluted to 20% of stock solution) QT-100 Example 21.25% CI-5 28.922 221.4988669 5.626 0.002 1 CNE (diluted to 20% of stocksolution) QT-1300 Example 2 1.25% CI-5 29.7 549.5832215 13.959 0.005 1CNE (diluted to 20% of stock solution) QT-100 Example 3 1.25% CI-528.922 293.3090019 7.450 0.004 1 CNE (diluted to 20% of stock solution)QT-1300 Example 3 1.25% CI-5 29.7 523.4829431 13.296 0.007 1 CNE(diluted to 20% of stock solution) QT-100 Example 4 1.25% CI- 28.922429.3436941 10.905 0.008 1 5CNE (diluted to 20% of stock solution)CI-5CNE refers to a corrosion package containing CI-5, KI and anon-emulsifier.

TABLE 17 Corrosion testing comparison between MEA-HCl using variousadditives—run time of 6 hours on various steel coupons at a temperatureof 90° C. (coupon density of 7.86 g/cc) Corrosion Surface area CouponFluid Package (cm²) Mils/yr Mm/year Lb/ft² P110 Example 2 0.5% CI-5CNE34.839 215.158445 5.465 0.006 (diluted to 20% of stock solution) QT-100Example 2 0.5% CI-5CNE 30.129 244.1796076 6.202 0.007 (diluted to 20% ofstock solution) QT-1300 Example 2 0.5% CI-5CNE 32.064 329.1078442 8.3590.009 (diluted to 20% of stock solution) P110 Example 2 0.5% CI-5CNE34.839 221.8755867 5.636 0.006 (diluted to 20% of stock solution) QT-100Example 2 0.5% CI-5CNE 30.129 276.7045255 7.028 0.008 (diluted to 20% ofstock solution) QT-1300 Example 2 0.5% CI-5CNE 32.064 342.56409 8.7010.010 (diluted to 20% of stock solution)

TABLE 18 Corrosion testing comparison between MEA-HCl using variousadditives—run time of 4 hours on L80 steel coupons at a temperature of150° C. (coupon density of 7.86 g/cc) Corrosion Surface Fluid Packagearea (cm²) Mils/yr Mm/year Lb/ft2 Example 2  3.0% CI-5 31.8061361.945612 34.593 0.025 (50%  0.3% CI-1A dilution) Example 2  2.5% CI-531.806 1575.428604 40.016 0.029 (50% 0.25% CI-1A dilution)

TABLE 19 Corrosion testing comparison between MEA-HCl using variousadditives—various run time on L80 steel coupons at a temperature of 150°C. (coupon density of 7.86 g/cc) (surface area of coupons of 31.806 cm²)Run time Corrosion Fluid (hours) Package Mils/yr Mm/year Lb/ft2 Example3 4  2.5% CI-5 1455.409087 36.967 0.027 (50% 0.25% CI-1A dilution)Example 3 4  3.0% CI-5 1308.14376 33.227 0.024 (50%  0.3% CI-1Adilution) Example 3 4  3.0% CI-5 958.7766021 24.353 0.018 (50%  0.3%CI-1A dilution)  1.0% 6-3 Example 3 4 2.75% CI-5 1047.066822 26.5950.019 (50% 0.25% CI-1A dilution)  1.0% 6-3 Example 3 4 2.75% CI-51672.685799 42.486 0.031 (50% 0.25% CI-1A dilution)  2.0% 6-3 Example 35  3.0% CI-5 1338.424546 33.996 0.031 (50%  0.3% CI-1A dilution)  l.0%6-3

6-3 refers to a short chain ethoxylate of C6 and 3 ethoxylate groupsacting as a non-ionic surfactant/solvent.

TABLE 20 Corrosion testing comparison between MEA-HCl using variousadditives—various run time on various steel coupons at a temperature of120° C. (coupon density of 7.86 g/cc) (surface area of coupons of 31.806cm²) Run time Corrosion Surface area Coupon Fluid (hours) Package (cm²)Mils/yr Mm/year Lb/ft² P110 Example 1 6 0.90% CI- 28.922 787.888663620.012 0.022 (diluted to 5CNE 20% of stock solution) QT-900 Example 1 60.90% CI- 34.31 1283.771913 32.608 0.036 (diluted to 5CNE 20% of stocksolution) P110 Example 1 6 1.0% CI- 28.922 875.6285116 22.241 0.025(diluted to 5CNE 20% of stock solution) P110 Example 1 6 1.25% CI-28.922 602.5477167 15.305 0.017 (diluted to 5CNE 20% of stock solution)P110 Example 1 6 1.5% CI- 28.922 787.635811 20.006 0.022 (diluted to5CNE 20% of stock solution) QT-100 Example 1 2 1.25% CI- 28.922221.4988669 5.626 0.002 (diluted to 5CNE 20% of stock solution) QT-1300Example 1 2 1.25% CI- 29.7 549.5832215 13.959 0.005 (diluted to 5CNE 20%of stock solution) QT-100 Example 1 3 1.25% CI- 28.922 293.3090019 7.4500.004 (diluted to 5CNE 20% of stock solution) QT-1300 Example 1 3 1.25%CI- 29.7 523.4829431 13.296 0.007 (diluted to 5CNE 20% of stocksolution) QT-100 Example 1 4 1.25% CI- 28.922 429.3436941 10.905 0.008(diluted to 5CNE 20% of stock solution)

TABLE 21 Corrosion testing comparison between MEA-HCl using variousadditive—run time of 6 hours on various steel coupons at a temperatureof 90° C. (coupon density of 7.86 g/cc) Surface Corrosion area Mm/ Lb/Coupon Fluid Package (cm²) Mils/yr year ft² P110 Example 2 0.5% 34.839215.158445 5.465 0.006 (diluted to CI-5CNE 20%) QT-100 Example 2 0.5%30.129 244.1796076 6.202 0.007 (diluted to CI-5CNE 20%) QT-1300 Example2 0.5% 32.064 329.1078442 8.359 0.009 (diluted to CI-5CNE 20%) P110Example 2 0.5% 34.839 221.8755867 5.636 0.006 (diluted to CI-5CNE 20%)QT-100 Example 2 0.5% 30.129 276.7045255 7.028 0.008 (diluted to CI-5CNE20%) QT-1300 Example 2 0.5% 32.064 342.56409 8.701 0.010 (diluted toCI-5CNE 20%)

CI5-CNE is the corrosion inhibitor CI-5 combined with potassium iodidedissolved therein and with a non-emulsifier

TABLE 22 Corrosion testing comparison between MEA-HCl using variousadditives—run time of 4 hours on L80 steel coupons at a temperature of150° C. (coupon density of 7.86 g/cc) (surface area of coupons of 31.806cm²) Corrosion Coupon Fluid Package Mils/yr Mm/year Lb/ft2 L80 Example 2 3.0% CI-5 1361.945612 34.593 0.025 (diluted to  0.3% CI-1A 50%) L80Example 2  2.5% CI-5 1575.428604 40.016 0.029 (diluted to 0.25% CI-1A50%)

TABLE 23 Corrosion testing comparison between MEA-HCl using variousadditives—various run times on L80 steel coupons at a temperature of150° C. (coupon density of 7.86 g/cc) (surface area of coupons of 31.806cm²) Run time Corrosion Fluid (hours) Package Mils/yr Mm/year Lb/ft2Example 3 4  2.5% CI-5 1455.409087 36.967 0.027 (diluted to 0.25% CI-1A50%) Example 3 4  3.0% CI-5 1308.14376 33.227 0.024 (diluted to  0.3%CI-1A 50%) Example 3 4  3.0% CI-5 (diluted to  0.3% CI-1A 958.776602124.353 0.018 50%)  1.0% 6-3 Example 3 4 2.75% CI-5 (diluted to 0.25%CI-1A 1047.066822 26.595 0.019 50%)  1.0% 6-3 Example 3 4 2.75% CI-5(diluted to 0.25% CI-1A 1672.685799 42.486 0.031 50%)  2.0% 6-3 Example3 5  3.0% CI-5 (diluted to  0.3% CI-1A 1338.424546 33.996 0.031 50%) 1.0% 6-3

With respect to the corrosion impact of the composition on typicaloilfield grade steel, it was established that it was clearly well belowthe acceptable corrosion limits set by industry for certainapplications, such as spearhead applications or lower temperature scaletreatments.

The corrosion testing carried out helps to determine the impact of theuse of such modified acid composition according to the present inventioncompared to the industry standard (HCl blends or any other mineral ororganic acid blends) when exposed to a variety of temperatures and steelgrades.

The results obtained for the composition containing only HCl were usedas a baseline to compare the other compositions. The results of Table 3show that a composition according to a preferred embodiment of thepresent invention shows substantial improvement (more than two timesbetter) when compared to a 15% HCl solution when exposed to coupons of1018 steel at a temperature of 110° C. for a period of 6 hours.

Additionally, compositions according to preferred embodiments of thepresent invention will allow the end user to utilize an alternative toconventional acids that have the down-hole performance advantages,transportation and/or storage advantages as well as the health, safetyand environmental advantages. Enhancement in corrosion control is anadvantage of the present invention versus the use of HCl at temperaturesabove 90° C. The reduction in skin corrosiveness, the controlledspending nature, and the high salt tolerance are other advantagesdepending on the preferred embodiments of the compositions according tothe present invention.

Dissolution Testing

In order to assess the effectiveness of the modified acid according to apreferred embodiment of the present invention, dissolution testing wascarried out to study the dissolution power of various compositions uponexposure to calcium carbonate (Table 24) and dolomite (Table 25). Thetests were carried out at a temperature of 23° C. and were compared tothe efficacy of a solution of 15% HCl and 28% HCl. The results arereported in Tables 24 and 25 below.

TABLE 24 Dissolution results for various acid compositions and totalsolubility Initial Final Weight Acid Solubility Total Fluid WeightWeight Loss/g % Solubility—kg/m³ HCl 15% 20.0142 9.3023 10.7119 53.52214 HCl 15% 25.0018 15.4885 9.5133 38.05 190 HCl 28% 20.0032 0.992219.011 95.04 380 HCl 28% 25.0024 3.84442 21.15798 84.62 423 MEA:HCl1:5.8 15.0432 3.5958 11.4474 76.10 229 MEA:HCl 1:3.5 15.0434 5.96549.078 60.35 182 MEA:HCl 1:3.8 15.0422 5.0306 10.0116 66.56 200 MEA:HCl1:4.1 15.0134 4.1962 10.8172 72.05 216 MEA:HCl 1:4.7 15.0513 3.552311.499 76.40 230 MEA:HCl 1:6.4 15.0328 1.4028 13.63 90.67 273 MEA:HCl1:7 15.00576 0.2064 14.79936 98.62 296 MEA:HCl 1:9.9 18.5574 6.445818.5594 74.22 371 DEA:HCl 1:3.5 15.0222 5.6072 9.415 62.67 188 DEA:HCl1:4.1 15.0356 4.0526 10.983 73.05 220

TABLE 25 Acid Solubility Test with Crushed Dolomite (at 23° C.) using avolume of 50 ml of composition Fluid Initial Final Weight Acid TotalExample 1 15.032 5.5323 9.4997 63.20 190 Example 2 20.0028 6.867213.1356 65.67 263 Example 3 25.0089 8.8639 16.145 64.56 323 Example 1diluted at 10.0318 5.198 4.8338 48.18 97 Example 2 diluted at 15.02638.4886 6.5377 43.51 131 Example 3 diluted at 20.0024 11.8339 8.168540.84 163

Spend Rate

Tests were conducted to assess the reactivity of the compositionsaccording to preferred embodiment of the present invention.

Determination of Reaction Rate of Synthetic Acid at 60° C.

A predetermined amount of synthetic acid was heated to 60° C. in a waterbath. The solution was then placed on a balance and a pre-weighedcalcium carbonate tile was submerged in the heated solution. The weightwas recorded at every 1 minute interval for 30 minutes. From therecorded weight, the weight loss percentage was calculated and plottedas a function of time.

Based on the data obtained, the two varying concentrations of the samecomposition according to a preferred embodiment of the present inventionhad comparable spend rates when compared to two concentrations of acontrol acid composition (HCl at 15% and 28%). The graphicalrepresentation of the testing is illustrated in FIGS. 1 and 2.

Although this invention exhibits a more methodical reaction rate whencompared to 15% HCl, it is more reactive than most typical modified,complexed or synthetic acids at concentrations from 33% to 90%, comingvery close to the reaction rate of a 15% HCl at a 90% dilution (90%acid-10% water). Having a safer modified acid system that reactssubstantially faster than other safer modified acid systems isadvantageous in a spearhead application where the purpose of the acid isto clean up residual cement from perforations and assist in reducing thebreakdown or federate pressure during the early stages of a stimulationtreatment (frac or matrix). It is advantageous to have an acid systemthat can be stored on location as a concentrate (providing a high levelof safety even in concentrate form) that can then be deployed anddiluted or blended to the desired concentration on the fly. Whendifficult areas of the well treatment are encountered (high breakdownpressures) the concentration can be increased, thereby reducing the timeit takes to achieve the desired injection rate of the following fluidsystem.

Stability Testing

Testing was carried out using pressurized ageing cell with Teflon linerin order to assess the stability of the composition of Example 1 atvarious temperatures. The tests were conducted at a pressure of 400 psi.The results of the tests are reported in Table 26 below.

TABLE 26 Stability Test Using Pressurized Ageing Cell With Teflon LinerTest pH pH after Solubility Temp Pressure Duration before pH afterthermal before Fluid (° C.) (psi) (hours) spending spending treatment(kg/m³) Precipitation Example 150 400 16 0.2 2.5 2.2 110 NO 1 diluted to50% Example 175 400 16 0.15 2.4 2.3 110 NO 1 diluted to 50% Example 190400 18 0.17 2.6 2.5 110 NO 1 diluted to 50% Example 200 400 24 0.08 2.55.2 110 Slight brown 1 diluted organic to 50% material

Dermal Testing

The objective of this study was to evaluate the dermal irritancy andcorrosiveness of the composition of Example 1, following a singleapplication to the skin of compositions of MEA-HCl of 1:4.1 molar ratio.

The test surface (human skin located on the back of the hand) wasexposed to a composition of MEA-HCl of 1:4.1 molar ratio. Visualobservation of the exposed areas was carried out over time intervals of15, 30 45 and 60 minutes. The surface was washed after exposure andresults were recorded as visual observations of the skin surface.

Observations recorded show that there was no blistering or rednesseffect on the exposed skin during and after exposure of the compositiontested.

Dermal Testing (Rabbit Test)

A skin corrosion/dermal irritation study was conducted on albino rabbitsusing a composition of Example 1 to determine skin corrosion potentialof the test material.

The original animal was treated with 0.5 mL of undiluted test materialto permit predetermined observation times of treated sites for dermalirritation and defects. The first site dosed was washed and observed 3minutes later. A second site was dosed and wrapped for 1 hour, thenwashed; both first and second test sites were observed. A third sitedosed was wrapped for 4 hours. One hour after unwrapping and washing thethird site, all three test sites were observed for signs of skinirritation and/or corrosion. Based on results of the first dosed animal,each of two additional animals were then dosed on a single intact 4-hourtest site. Observations of all animals for dermal irritation and defectswere made at −1, 24, 48 and 72 hours, and (original animal only) 7, 10and 14 days after the 4-hour dose unwrap.

Tissue destruction (necrosis) was not observed in any animals within theskin corrosion evaluation period. The test material is considerednon-corrosive by DOT criteria when applied to intact skin of albinorabbits.

Dermal irritation was observed in two animals in the primary skinirritation segment of the test. A Primary Irritation Index (PII) of 1.3was obtained based on 1, 24, 48 and 72-hour observations (4-hourexposure site only) for irritation, and that value used to assign adescriptive rating of slightly irritating.

Iron Sulfide Scale Control

A composition according to a preferred embodiment of the presentinvention was tested for its ability to dissolve iron sulfide. Theperformance results were recorded in Table 27 below.

TABLE 27 Acid Solubility Test with Iron Sulfide (at 23° C.) Acid InitialFinal Weight Acid Total Volume Weight Weight Loss Solubility SolubilityFluid (ml) (g) (g) (g) (%) (kg/m³) Example 1 50 10.0002 1.5195 8.480784.81 170 Example 2 50 15.0019 3.2539 11.748 78.31 235 Example 3 5015.0048 1.0725 13.9323 92.85 279

The above results illustrate another valuable use of a compositionaccording to preferred embodiments of the present invention bysolubilising iron sulfide a commonly encountered oil field scale.

Elastomer Compatibility

When common sealing elements used in the oil and gas industry come incontact with acid compositions they tend to degrade or at least showsign of damage. A number of sealing elements common to activities inthis industry were exposed to a composition according to a preferredembodiment of the present invention to evaluate the impact of the latteron their integrity. More specifically, the hardening and drying and theloss of mechanical integrity of sealing elements can have substantialconsequences on the efficiency of certain processes as breakdownsrequire the replacement of defective sealing elements. Testing wascarried out to assess the impact of the exposure of composition ofExample 1 to various elastomers. Long term (72-hour exposure) elastomertesting on the concentrated product of Example 1 at 70° C. and 28,000kPa showed little to no degradation of various elastomers, includingNitrile® 70, Viton® 75, Aflas® 80 style sealing elements, the resultsare reported in Table 28. This indicates that the composition of Example1 is compatible with various elastomers typically found in the oil andgas industry.

TABLE 28 Elastomer compatibility data for 100% composition of Example1—3 days at 70° C. Weight Thickness Weight Weight Change/ before/Thickness Elastomer before/g after/g g mm after/mm Viton V75 240 0.34540.3556 −0.0102 3.47 3.55 Nitrile N70 240 0.2353 0.2437 −0.0084 3.53 3.5EPDM E70 126 0.114 0.1195 −0.0055 2.58 2.65

Wormholing Testing

Numerous studies of the wormholing process in carbonate acidizing haveshown that the dissolution pattern created by the flowing acid can becharacterized as one of three types (1) compact dissolution, in whichmost of the acid is spent near the rock face; (2) wormholing, in whichthe dissolution advances more rapidly at the tips of a small number ofhighly conductive micro-channels, i.e. wormholes, than at thesurrounding walls; and (3) uniform dissolution.

The dissolution pattern that is created depends on the interstitialvelocity, which is defined as the acid velocity flowing through theporous medium. Interstitial velocity is related to the injection rate(interstitial velocity=injection rate/(area of low porosity). Compactdissolution patterns are created at relatively low injection rates,wormhole patterns are created at intermediate rates and uniformdissolution patterns at high rates.

This interstitial velocity at the wormhole tip controls the wormholepropagation. The optimal acid injection rate is then calculated based ona semi-empirical flow correlation. At optimal injection rate, for agiven volume, acid penetrates the furthest into the formation, resultingin the most efficient outcome of the acid stimulation. Wormholestructures change from large-diameter at low interstitial velocity tothin wormholes at optimal velocity conditions, to more branched patternsat high interstitial velocity.

It has been well-accepted by the industry that the interstitial velocityyielding wormhole mode if the optimal interstitial velocity, at whichfor a given volume acid penetrates the furthest into the formation,resulting in the most efficient outcome of acid stimulation. Wormholestructures change from large-diameter at low interstitial velocity tothin wormholes at optimal condition, to more branched pattern at highinterstitial velocity. FIG. 3 shows an example illustrating threewormhole patterns.

This series of experimental testing study examined the composition ofExample 1 (diluted to a 90% concentration). This composition is designedas a low-hazard/low-corrosion aqueous synthetic acid enhanced throughthe addition of proprietary oilfield chemistry to replace standard HClblends, especially for high to ultra-high temperature.

The acid system according to the present invention was compared to 15%HCl under the exact same testing conditions. The wormhole efficiencycurve (pore volume to breakthrough vs interstitial velocity) wasdetermined for both acid systems for comparison. It was concluded thatthe composition tested has the similar optimal pore volume ofbreakthrough at about 11% lower value and about 18% lower of optimalinterstitial velocity compared with HCl.

Test Parameters

Two series of matrix acidizing experiments were conducted in order toevaluate the performance of the composition of Example 1 vs 15% HCl. Theexperiments utilized a 90% concentration of the composition of Example 1comprising 0.3 vol % common commercial corrosion inhibitor, and theother set of experiments utilized a 15% solution of HCl with 0.3 vol %of a corrosion inhibitor. The experiments were conducted utilizingIndiana limestone cores.

All cores were 1.5-inch in diameter and 8-inch in length. The averageporosity of the core samples was 14% and the average permeability was 13mD. The back pressure used in these experiments was 2000 psi. Thetesting temperature was 180° F. (82° C.). The limestone cores wereselected as they help in simulating the geology encountered mostcommonly in oilfields in North America.

Test Procedure

The matrix acidizing apparatus consists of a pumping system, anaccumulation system, a core containment cell, a pressure maintainingsystem, a heating system and a data acquisition system. A Teledyne Isco®syringe pump was used to inject water and acid at constant rates. Aback-pressure regulator was used to maintain the desired minimum systempressure at 2000 psi.

Confining pressure was set to 400-500 psi higher than the injectionpressure to avoid fluid leaking. Two heating tapes were used to heat thecore holder and the injection fluid for the high-temperature tests.During the experiment, the system was first pressurized by injectingwater, once the flow reached a steady state; permeability was calculatedfrom the measured pressure differential across the core containmentcell. The system was then heated to the experiment temperature. When thefull system; fluid, core containment cell and core reached the targettemperature, water injection was ceased and acid injection commenced.

Injection was ceased when wormholes breached the core and acid injectiontime was recorded for the breakthrough pore volume calculation. For eachexperimental condition, 4-6 individual tests were performed with thesame temperature and pressure parameters. The only condition thatchanged was the injection rate. The rate varied in a range until theoptimal condition was identified. The Buijse and Glasbergen (2005) modelwas utilized to generate the wormhole efficiency relationship by fittingthe experimental data obtained.

Core Properties

The cores utilized for testing were 1.5 inches in diameter and 8 incheslong. Indiana limestone samples were obtained from one sample of outcropto ensure linear properties.

Experimental Results

The experimental results for HCl are listed in Table 29 below. Theexperimental results for the composition of Example 1 (at 90%concentration) are listed in Table 30.

TABLE 29 Wormholing Experiment—Experimental Results for HCl Acidinjection rate Interstitial Velocity Pore Volume to Core# (ml/min)(cm/min) Breakthrough IC2 10 6.39 0.52 IC1 8 4.53 0.60 IC3 7 4.97 0.60IC5 5 3.47 0.51 IC6 3 2.10 0.47 IC16 2 1.56 0.64 IC18 0.8 0.62 2.93

TABLE 30 Wormholing Experiment—Experimental Results for the compositionof Example 1 (at 90% concentration) Acid injection rate InterstitialVelocity Pore Volume to Core# (ml/min) (cm/min) Breakthrough IC111 106.37 0.63 IC108 5 3.01 0.46 IC112 3 1.92 0.49 IC5109 2 1.2 0.57 ICA16 10.57 2.11

The optimal condition for two sets of experiments with Buijse andGlasbergen equation are listed in Table 31.

FIG. 4 is a graphical representation of the results of the wormholeefficiency relationship testing using a composition according to apreferred embodiment of the present invention. The data obtained andplotted correlates the Pore volume breakthrough as a function of theinterstitial velocity. The lowest point of each curve is considered toprovide the optimal condition for each acidic composition.

The CT scans for both the compositions of Example 1 (at 90%concentration) are shown in FIGS. 5A, B, C, D and E. The CT scan imagesfor core LDA16 (FIG. 5A), IC108 (FIG. 5D), IC109 (FIG. 5B), IC111 (FIG.5E) and IC112 (FIG. 5C). The images are arranged from the lowestinterstitial velocity (0.57 cm/min) to highest interstitial velocity(6.37 cm/min). The wormholing behavior follows the conventional pattern:at low interstitial velocity, the wormholes are more branched and athigh interstitial velocity, the wormholes are more uniform and straight.

TABLE 31 Optimal Condition Obtained from Experimental Results fromWormholing Experimeny #1 Optimal condition HCl Example 1 (90% conc.)PV_(bt-optimal) 0.46 0.41 V_(i-opt) 1.97 1.62 PV_(bt-optimal difference)11% V_(i-optimal difference) 18%

According to the optimal wormhole efficiency theory, wormhole diameteris supposed to increase when the injection velocity decreases and thestimulation begins losing efficiency at low injection rates. This is notobserved during this study utilizing the composition of Example 1 (at90% concentration). At a low injection rate (0.8 ml/min (0.5 cm/min))the HCl core developed a large-diameter wormhole and the wormholepropagation velocity is slow. The test stopped because the sleeve forconfining pressure was broken by compact dissolution exhibited with HCl.On the contrast, the composition of Example 1 (at 90% concentration)showed a wormhole diameter similar to the more optimal injection rate(higher injection rate). At 1.2 cm/min, the wormholes created by thecomposition of Example 1 (at 90% concentration) were much smaller(desired) than the ones created by the 15% HCl composition. This showsthat the composition of Example 1 (at 90% concentration) according apreferred embodiment of the present invention has higher stimulationefficiency in general compared with HCl, especially at lower injectionrate.

Preliminary observations of wormhole efficiency tests: the optimalinterstitial velocity for the composition of Example 1 (at 90%concentration) is lower than 15% HCl, providing an advantage over HClacid system test. This feature helps to reduce the requirements of highinjection rates typically utilized in field operations to achieve anylevel of efficiency with regards to wormholing performance; the optimalpore volume to breakthrough for the composition of Example 1 (at 90%concentration) is similar (optimal) to 15% HCl. With other retardedacids, they tend to have lower optimal interstitial velocity. Most ofthem, if not all, have higher optimal pore volume of breakthroughbecause of lower reaction rates. The composition of Example 1 (at 90%concentration) does not exhibit an increased PV_(bt,opt); and it hasadvantageous potential when compared to 15% HCl from a wormholeperformance perspective. The benefit is more pronounced at lowinterstitial velocity. For injection-rate limited applications, thecomposition according to the present invention may reduce the acidvolume required 2-4 times with the same stimulation outcome.

Wormholing Performance

In order to compare the wormholing performance of the composition ofExample 1 (at 90% conc.) and a 15% HCl composition, some modeling workwas done at two interstitial velocity values.

To compare their performance, v_(i) near Example 1's optimal conditionand at a lower condition were modeled. Table 32 contains thecorresponding PV_(bt) values at selected v_(i).

TABLE 32 Modeling Conditions for the composition of Example 1 (90%conc.) and 15% HCl Modeling Conditions HCl Example 1 (90% conc.) Case 1v_(i, 1) 1.6 1.6 PV_(bt, 1) 0.49 0.41 Case 2 v_(i, 2) 0.6 0.6 PV_(bt, 2)3.23 2.11

Modeling work followed Buijse-Glasbergen model of wormhole propagation.The equation is as following:

$\begin{matrix}{v_{wh} = {\left( \frac{v_{i}}{{PV}_{{bt},n}} \right) \times \left( \frac{v_{i}}{v_{i,n}} \right)^{- \gamma} \times \left\{ {1 - {\exp \left\lbrack {{- 4}\left( \frac{v_{i}}{v_{i,n}} \right)^{2}} \right\rbrack}} \right\}^{2}}} & (1)\end{matrix}$

For each of the cases, the PV_(bt,n) and v_(i,n) values were varied toassess the acid performance by comparing the v_(wh) values. The wormholelength at each time step was calculated by simply computing how muchwormhole has increased by multiplying the wormhole tip velocity to thetime step (in this case 0.1 min) and adding to the wormhole length atprevious time step.

r _(wh) =r _(wi) +v _(wh)*0.1  (2)

Skin was calculated with simplified Hawkins' formula.

$\begin{matrix}{s = {- {\ln \left( \frac{r_{wh}}{r_{w}} \right)}}} & (3)\end{matrix}$

The overall productivity index was calculated with formula 4 below:

$\begin{matrix}{J_{D} = \frac{1}{{\ln \left( \frac{r_{e}}{r_{w}} \right)} + s}} & (4)\end{matrix}$

Then the productivity of each acid was compared with the J_(D) values atoverall skin of 0 and 10.

$\begin{matrix}{\frac{J_{D}}{J_{D_{s}}} = \frac{\ln \left( \frac{r_{e}}{r_{w}} \right)}{{\ln \left( \frac{r_{e}}{r_{w}} \right)} + s}} & (5)\end{matrix}$

where the skin term will have the value of either 0 or 10. Then thisratio was graphed with the volume of acid used. For the sake of thecalculation, injection rate of 2 bpm, porosity of 14%, wellborethickness of 1,000 ft, initial wellbore radius of 0.4 ft, reservoirradius of 2,980 ft, wellbore pressure of 3,000 psi, reservoir pressureof 5,000 psi, permeability of 30 mD, fluid viscosity of 1 cp, andformation volume factor of 1.117 were assumed.

FIGS. 6 to 10 are the graphs generated with these conditions. The fourcurves represent the performance of both compositions at two differentinterstitial velocities (the HCl composition (15%) and the compositionof Example 1 (at 90% conc.) both at 0.6 and 1.6 cm/min). FIG. 6 is agraphical representation of the skin evolution over injection volume forHCl (15%) and the composition of Example 1 (90% conc.). FIG. 7 is agraphical representation of the stimulated productivity index over timefor HCl (15%) and the composition of Example 1 (90% conc.). FIG. 8 is agraphical representation of the wormhole penetration length over totalinjection volume for HCl (15%) and the composition of Example 1 (90%conc.). FIG. 9 is a graphical representation of the productivity indexcomparison at 0 skin for HCl (15%) and the composition of Example 1 (90%conc.). FIG. 10 is a graphical representation of the productivity indexcomparison at 10 skins for HCl (15%) and the composition of Example 1(90% conc.).

As can be seen from the FIGS. 6 to 10, the composition of Example 1 (at90% concentration) shows a clear superior performance at lowinterstitial velocity in comparison to a 15% HCl composition. This meansthat if the acid stimulation operation has a limitation for pumping ratebelow 15% HCl's optimum interstitial velocity, the composition ofexample 1 (at 90% conc.) has definite advantage compared to 15% HCl.

Environmental Testing

A series of test were carried out to assess the environmental impact ofmonoethanoamine. A stock solution of 98-99% pure monoethanolamine wassent to be tested. The solution was diluted where necessary.

Determination of Acute Lethal Toxicity to Marine Copepods (Copepoda;Crustacea) (ISO 14669 (1999) Water Quality)

This study was commissioned to determine the aquatic phase toxicity ofmonoethanolamine to the marine copepod Acartia tonsa. The A. tonsatoxicity LC₅₀ test was conducted in accordance with the study planexcept for the following deviation and interferences but met all otherrelevant validity criteria. In the definitive test the temperature ofthe dilution water was below acceptable limits by a maximum of 0.7° C.,the pH was below acceptable limits by a maximum of 0.01 units. Thesedeviations were not expected to have an impact on the test as there wasno control mortalities.

In the range-finding test composition of monoethanolamine exhibited a 48h LC₅₀ value of 550 mg/l (Water Accommodated Fraction (WAF)) to themarine copepod A. tonsa in the aqueous phase. The result was based onnominal concentrations and was calculated by Linear Interpolation withinthe CETIS suite of statistical analysis. There was <10% controlmortality observed throughout the range-finding test. In the definitivetest, the composition of monoethanolamine exhibited a 48 h LC₅₀ value of434 mg/l in seawater (Water Accommodated Fraction (WAF)) to the marinecopepod A. tonsa in the aqueous phase. The result was based on nominalconcentrations and was calculated by Linear Interpolation within theCETIS suite of statistical analysis. There were <10% control mortalityobserved throughout the definitive test.

OSPARCOM Guidelines (2006) Part A. A Sediment Bioassay Using an AmphipodCorophium sp

This study was commissioned to determine the sediment phase toxicity ofthe composition of monoethanolamine to the intertidal amphipod Corophiumvolutator. The C. volutator toxicity LC₅₀ test was conducted inaccordance with the study plan and met all relevant validity criteria.The pH at the 10,000 mg/kg (nominal weight) replicates showed a muchhigher pH compared to the normal required range of 7.5-8.5, this is adirect effect of the test material itself. The composition ofmonoethanolamine exhibited a 10 day LC₅₀ value of 6,660 mg/kg (via driedsediment) to the marine amphipod C. volutator in the sediment phase. Theresult is based on nominal concentrations and was calculated by LinearInterpolation within the CETIS suite of statistical analysis.

ISO 10253 (2016) Water Quality—Marine Algal Growth Inhibition Test withSkeletonema Sp.

This study was commissioned to determine the aquatic phase toxicity ofthe composition of monoethanolamine to the marine unicellular algaeSkeletonema sp. The Skeletonema sp. toxicity EC(r)50 test was conductedin accordance with the study plan and met all relevant validitycriteria. It is the results from this test that has been reported.Observations showed that the pH for a 1000 mg/l stock resulted in aphysical change, the stock went from cloudy to clear therefore theunadjusted stocks were used for the range-finding test and definitivetest apart from the 100 mg/l stock, there was no physical changeobserved.

In the range-finding test, the composition of monoethanolamine exhibiteda 72 h EC(r)50 value of 509 mg/l (WAFs) to the marine phytoplanktonSkeletonema sp. in the aqueous phase. The result is based on nominalconcentrations and was calculated by Linear Interpolation within theCETIS suite of statistical analysis. In the definitive test,monoethanolamine exhibited a 72 h EC(r)50 value of 199.7 mg/l (WAFs) tothe marine phytoplankton Skeletonema sp. in the aqueous phase. Theresult is based on nominal concentrations and was calculated by LinearInterpolation within the CETIS suite of statistical analysis.

Assessment of Aerobic Degradability of the Composition of Example 1 inSeawater (OECD 306 Method)

This study was commissioned to determine the aerobic degradability ofthe composition of monoethanolamine in seawater. The test was conductedin accordance with the study plan and met all relevant validitycriteria. There were no deviations in this test. The ThOD_(NO3) valuewas determined from the chemical formula of the compound tested. Therewere nitrogen containing components present, therefore fullnitrification was assumed.

The oxygen blank degradation was within formal limits of acceptability.The soluble reference material, sodium benzoate, degraded by more than60% in the first 14 days, indicating that the seawater used in the testcontained a satisfactory population of viable bacteria. The seawaterdata collected confirms the microbial count for seawater used in thistest was within acceptable limits.

According to the biodegradation data with nitrification taken intoaccount the composition of monoethanolamine biodegraded by 71% over 28days. The test material appeared to biodegrade rapidly during the first7 days, the rate slowed down between days 14 and 21. However, during thelast 7 days the rate increased to reach a maximum biodegradation of 71%on the final day of the 28-day study.

The OECD 306 guideline states the test material can be considered to beinhibitory to bacteria (at the concentration used) if the BOD of themixture of reference and test materials is less than the sum of the BODof the separate solutions of the two substances. Within this test, thecomposition showed a low percentage inhibition of 12% in 28 days.

Assessment of the Toxicity of the Composition of Example 1 to the MarineFish Cvprinodon variegatus (OSPAR Limit Test)

This study was commissioned to determine the aquatic (96 h limit test)toxicity of the composition of monoethanolamine to the marine fishCyprinodon variegatus.

The 96 h fish limit test was conducted in accordance with the study planand met all relevant validity criteria. There were no interferences inthis test. Test conditions of exposure were within formal and informallimits of acceptability except for the exception noted below. There wereten fish used in both the test and control tanks, with no controlmortality observed. The pH was not adjusted as the adjustment of pHcaused a physical change in the test material stock in an allied study;the assessment of the toxicity (48 h LC₅₀) of the composition tested tothe marine copepod Acartia tonsa (2356-1).

The test concentration was derived from the test material EC/LC₅₀ valuebetween the most sensitive acute toxicity test species Skeletonema sp.and A. tonsa. From allied studies, the algal species Skeletonema sp. wasnoted to be more sensitive with an EC₅₀ value of 199.7 mg/l.

After 96 h exposure to the composition of monoethanolamine, nomortalities were observed in the marine fish C. variegatus. Therefore,it can be concluded that the composition exhibited no effect at 199.7mg/l after 96 h of exposure (Water Accommodated Fraction) to the marinefish C. variegatus in the water phase.

Uses of Compositions According to Preferred Embodiments of the PresentInvention

Table 33 lists a number of potential uses (or applications) of thecompositions according to the present invention upon dilution thereofranging from approximately 1 to 90% dilution, include, but are notlimited to: injection/disposal treatments; matrix acid squeezes, soaksor bullheads; acid fracturing, acid washes; fracturing spearheads(breakdowns); pipeline scale treatments, cement breakdowns orperforation cleaning; pH control; and de-scaling applications, hightemperature (up to 190° C.) cyclical steam scale treatments and steamassisted gravity drainage (SAGD) scale treatments (up to 190° C.).

The methods of use generally comprise the following steps: providing acomposition according to a preferred embodiment of the present; exposinga surface (such as a metal surface) to the aqueous modified acidcomposition; allowing the aqueous modified acid composition a sufficientperiod of time to act upon said surface; and optionally, removing theacid composition when the exposure time has been determined to besufficient for the operation to be complete or sufficiently complete.Another method of use comprises: injecting the aqueous modified acidcomposition into a well and allowing sufficient time for the aqueousmodified acid composition to perform its desired function, subsequentlyremoving the acid composition from the well to stop the acid exposure.Yet another method of use comprises: exposing the aqueous modified acidcomposition to a body of fluid (typically water) requiring a decrease inthe pH and allowing sufficient exposure time for the aqueous modifiedacid composition to lower the pH to the desired level.

TABLE 33 Applications for which compositions according to the presentinvention can be used as well as proposed dilution ranges ApplicationSuggested Benefits Injection/Disposal 10%-75% Compatible with mutualsolvents and solvent blends, Squeezes & Soaks 33%-75% Ease of storage &handling, cost Bullhead effective compared to conventional Annular acidstimulations. Ability to leave pump equipment in wellbore. AcidFracs/matrix 50%-90% Decreased shipping and storage treatments comparedto conventional acid, no blend separation issues, comprehensive spendrate encourages deeper formation penetration. Frac Spearheads 33%-90%Able to adjust concentrations on the (Break-downs) fly. Decreasedshipping and storage on location. Cement Break-downs 20%-90% Higherconcentrations recommended due to lower temperatures, and reducedsolubility of aged cement. pH Control 0.1%-1.0% Used in a variety ofapplications to adjust pH level of water based systems. LinerDe-Scaling,  1%-25% Continuous injection/de-scaling of Heavy Oil slottedliners, typically at very high temperatures.

The main advantages of the use of the modified acid compositionincluded: the reduction of the total loads of acid being transported,and the required number of tanks by delivering concentrated product tolocation and diluting with fluids available on location, or nearlocation (with fresh or low to high salinity production water). Anotheradvantage of a preferred embodiment of the present invention includesthe decreased the load of corrosion inhibitor. Other advantages ofpreferred embodiments of the composition according to the presentinvention include: operational efficiencies which lead to theelimination of having to periodically circulate tanks of HCl acid due tocorrosion control chemical additive separation; reduced corrosion todownhole tubulars; temperature corrosion protection up to 190° C., lessfacility disruptions due to iron or metals precipitation in the oiltreating process and precipitation of solubilized carbonate at lower pHlevels, thermal stability of a modified acid, and reduced hazardous HClacid exposure to personnel and environment by having a low hazard, lowfuming acid (lower vapour pressure) having low or no dermalcorrosiveness.

A modified acid composition according to a preferred embodiment of thepresent invention, can be used to treat scale formation in SAGD or CSS(cyclical stream) operations at high temperatures (up to 190° C.) whileachieving time dependent acceptable corrosion limits set by industry(typically two to three hours at elevated temperatures). This alsoeliminates the need for the SAGD or CSS operations to be halted for a“cool down prior to a scale treatment and said modified acid is injectedinto said well to treat scale formation inside said well at hightemperatures greatly reducing down-time and lost revenue for theoperator.

While the foregoing invention has been described in some detail forpurposes of clarity and understanding, it will be appreciated by thoseskilled in the relevant arts, once they have been made familiar withthis disclosure that various changes in form and detail can be madewithout departing from the true scope of the invention in the appendedclaims.

1. An aqueous modified acid composition comprising: a mineral acid andan alkanolamine in a molar ratio of not more than 15:1.
 2. A aqueousmodified acid composition comprising: hydrochloric acid and analkanolamine in a molar ratio of not more than 15:1.
 3. The aqueousmodified acid composition according to claim 2, wherein the hydrochloricacid and alkanolamine are present in a molar ratio of not more than10:1.
 4. The aqueous modified acid composition according to claim 2,wherein the hydrochloric acid and alkanolamine are present in a molarratio of not more than 7.0:1.
 5. The aqueous modified acid compositionaccording to claim 2, wherein the hydrochloric acid and alkanolamine arepresent in a molar ratio of not more than 4.1:1.
 6. The aqueous modifiedacid composition according to claim 2, wherein the hydrochloric acid andalkanolamine are present in a molar ratio of not less than 3:1.
 7. Theaqueous modified acid composition according to any one of claims 1 to 6,wherein the alkanolamine is selected from the group consisting of:monoethanolamine; diethanolamine; triethanolamine and combinationsthereof.
 8. The aqueous modified acid composition according to any oneof claims 1 to 7, wherein the alkanolamine is monoethanolamine.
 9. Theaqueous modified acid composition according to any one of claims 1 to 7,wherein the alkanolamine is diethanolamine.
 10. The aqueous modifiedacid composition according to any one of claims 1 to 9, furthercomprising a metal iodide or iodate.
 11. The composition according toclaim 1, wherein the mineral acid is selected from the group consistingof: HCl, nitric acid, sulfuric acid, sulfonic acid, phosphoric acid, andcombinations thereof.
 12. The aqueous modified acid compositionaccording to any one of claims 1 to 11, further comprising a metaliodide or iodate.
 13. The modified acid composition according to any oneof claims 1 to 12, further comprising an alcohol or derivative thereof.14. The modified acid composition according to claim 12, wherein themetal iodide or iodate is selected from the group consisting of: cuprousiodide; potassium iodide; sodium iodide; lithium iodide and combinationsthereof.
 15. The modified acid composition according to claim 12,wherein the metal iodide or iodate is potassium iodide.
 16. The modifiedacid composition according to any one of claims 13 to 15, wherein thealcohol or derivative thereof is an alkynyl alcohol or derivativethereof.
 17. The modified acid composition according to claim 16,wherein the alkynyl alcohol or derivative thereof is propargyl alcoholor a derivative thereof.
 18. The modified acid composition according toclaim 16, wherein the alkynyl alcohol or derivative thereof is presentin a concentration ranging from 0.01 to 5% w/w.
 19. The modified acidcomposition according to claim 16, wherein the alkynyl alcohol orderivative thereof is present in a concentration of 0.2% w/w.
 20. Themodified acid composition according to any one of claims 12 to 19,wherein the metal iodide is present in a concentration ranging from 0.1to 2% by weight of the total weight of the composition.
 21. The modifiedacid of any one of claims 1 to 20 further comprising a corrosioninhibitor comprising a α,β-unsaturated aldehyde with no methyl group atthe alpha position.
 22. The modified acid according to claim 21, wherethe α,β-unsaturated aldehyde with no methyl group at the alpha positionis selected from the group consisting of: citral and cinnamaldehyde 23.The use of a modified acid composition according to any one of claims 1to 22 in the oil industry—wherein the use comprises an activity selectedfrom the group consisting of: stimulate formations; assist in reducingbreakdown pressures during downhole pumping operations; treat wellborefilter cake post drilling operations; assist in freeing stuck pipe;descale pipelines and/or production wells; increase injectivity ofinjection wells; lower the pH of a fluid; remove undesirable scale on asurface selected from the group consisting of: equipment, wells andrelated equipment and facilities; fracture wells; matrix stimulations;conduct annular and bullhead squeezes & soaks; pickle tubing, pipeand/or coiled tubing; increase effective permeability of formations;reduce or remove wellbore damage; clean perforations; and solubilizelimestone, dolomite, calcite and combinations thereof.
 24. The use of amodified acid composition according to any one of claims 1 to 22 in themining industry said use being selected from the group consisting of:treating scale and adjusting pH levels in fluid systems.
 25. The use ofa modified acid composition according to any one of claims 1 to 22 inthe water treatment industry said use being selected from the groupconsisting of: adjusting pH and neutralizing alkaline effluent.
 26. Theuse of a modified acid composition according to any one of claims 1 to22 in the fertilizer/landscaping industry to adjust the pH level of asoil.
 27. The use of a modified acid composition according to any one ofclaims 1 to 22 to regenerate ion exchange beds.
 28. The use of amodified acid composition according to any one of claims 1 to 22 in theconstruction industry said use being selected from the group consistingof: etching concrete and cleaning concrete from equipment and buildings.29. The use of a modified acid composition according to any one ofclaims 1 to 22 in the electrical generation industry, said use beingselected from the group consisting of: descaling pipelines and relatedequipment and descaling facilities.
 30. The use of a modified acidcomposition according to any one of claims 1 to 22 in the food and dairyindustry, said use being selected from the group consisting of:manufacturing protein, manufacturing starch, demineralizing whey,manufacturing casein and regenerating ion exchange resins.
 31. The useof a modified acid composition according to any one of claims 1 to 22 inthe pool industry to lower the pH of fluids.
 32. The use of a modifiedacid composition according to any one of claims 1 to 22 in themanufacturing industry to perform an operation selected from the groupconsisting of: pickling steel and cleaning metal.
 33. The use of amodified acid composition according to any one of claims 1 to 22 in theretail industry as a low pH cleaning additive.